Oil & Gas Wells
In the context of production from a well, oil and gas are understood to refer to crude oil and natural gas. Oil and gas are naturally occurring hydrocarbons in certain subterranean formations.
A subterranean formation containing oil or gas may be located under land or under the seabed off shore. Oil and gas reservoirs are typically located in the range of a few hundred feet (shallow reservoirs) to a few tens of thousands of feet (ultra-deep reservoirs) below the surface of the land or seabed.
To produce oil or gas, a well is drilled into a subterranean formation that is an oil or gas reservoir. Typically, a well must be drilled hundreds or thousands of feet into the earth to reach an oil or gas reservoir. Generally, the greater the depth of the formation, the higher the static temperature and pressure of the formation.
Generally, well services include a wide variety of operations that may be performed in oil, gas, geothermal, or water wells, such as drilling, cementing, completion, and intervention. These well services are designed to facilitate or enhance the production of desirable fluids such as oil or gas from or through a subterranean formation. A well service usually involves introducing a well fluid into a well.
Drilling and Drilling Fluids
In general, drilling is the process of drilling the wellbore. After the hole is drilled, sections of steel pipe, referred to as casing, which are slightly smaller in diameter than the borehole, are placed in at least the uppermost portions of the wellbore. The casing provides structural integrity to the newly drilled borehole.
The well is created by drilling a hole into the earth (or seabed) with a drilling rig that rotates a drill string with a drilling bit attached to the downward end. Usually the borehole is anywhere between about 5 inches (13 cm) to about 36 inches (91 cm) in diameter. The borehole usually is stepped down to a smaller diameter the deeper the wellbore as upper portions are cased or lined, which means that progressively smaller drilling strings and bits must be used to pass through the uphole casing or liner.
While drilling an oil or gas well, a drilling fluid is circulated downhole through a drillpipe to a drill bit at the downhole end, out through the drill bit into the wellbore, and then back uphole to the surface through the annular path between the tubular drillpipe and the borehole. The purpose of the drilling fluid is to maintain hydrostatic pressure in the wellbore, to lubricate the drill string, and to carry rock cuttings out from the wellbore.
The drilling fluid can be water-based or oil-based. Oil-based fluids tend to have better lubricating properties than water-based fluids, nevertheless, other factors can mitigate in favor of using a water-based drilling fluid.
In addition, the drilling fluid may be viscosified to help suspend and carry rock cuttings out from the wellbore. Rock cuttings can range in size from silt-sized particles to chunks measured in centimeters. Carrying capacity refers to the ability of a circulating drilling fluid to transport rock cuttings out of a wellbore. Other terms for carrying capacity include hole-cleaning capacity and cuttings lifting.
An example a water-based drilling fluid is a drilling mud, which includes an aqueous solution and undissolved solids (as solid suspensions). A water-based drilling mud can be based on a brine. Both the dissolved solids and the undissolved solids can be chosen to help increase the density of the drilling fluid. An example of an undissolved weighting agent is barite (barium sulfate). The density of a drilling mud can be much higher than that of typical seawater or even higher than high-density brines due to the presence of suspended solids.
Cementing and Hydraulic Cement Compositions
Cementing is a common well operation. For example, hydraulic cement compositions can be used in cementing operations in which a string of pipe, such as casing or liner, is cemented in a wellbore. The cement stabilizes the pipe in the wellbore and prevents undesirable migration of fluids along the wellbore between various zones of subterranean formations penetrated by the wellbore. Where the wellbore penetrates into a hydrocarbon-bearing zone of a subterranean formation, the casing can later be perforated to allow fluid communication between the zone and the wellbore. The cemented casing also enables subsequent or remedial separation or isolation of one or more production zones of the wellbore, for example, by using downhole tools such as packers or plugs, or by using other techniques, such as forming sand plugs or placing cement in the perforations. Hydraulic cement compositions can also be utilized in intervention operations, such as in plugging highly permeable zones or fractures in zones that may be producing too much water, plugging cracks or holes in pipe strings, and the like.
In performing cementing, a hydraulic cement composition is pumped as a fluid (typically in the form of suspension or slurry) into a desired location in the wellbore. For example, in cementing a casing or liner, the hydraulic cement composition is pumped into the annular space between the exterior surfaces of a pipe string and the borehole (that is, the wall of the wellbore). The cement composition is allowed time to set in the annular space, thereby forming an annular sheath of hardened, substantially impermeable cement. The hardened cement supports and positions the pipe string in the wellbore and bonds the exterior surfaces of the pipe string to the walls of the wellbore.
Hydraulic cement is a material that when mixed with water hardens or sets over time because of a chemical reaction with the water. Because this is a chemical reaction with the water, hydraulic cement is capable of setting even under water. The hydraulic cement, water, and any other components are mixed to form a hydraulic cement composition in the initial state of a slurry, which should be a fluid for a sufficient time before setting for pumping the composition into the wellbore and for placement in a desired downhole location in the well.
Completion or Intervention
After drilling and cementing the casing, completion is the process of making a well ready for production or injection. This principally involves preparing a zone of the wellbore to the required specifications, running in the production tubing and associated downhole equipment, as well as perforating and stimulating as required.
Intervention is any operation carried out on a well during or at the end of its productive life that alters the state of the well or well geometry, provides well diagnostics, or manages the production of the well. Workover can broadly refer to any kind of well intervention that involves invasive techniques, such as wireline, coiled tubing, or snubbing. More specifically, though, workover refers to the process of pulling and replacing a completion.
Common Well Treatments in Well Services
Well services can include various types of treatments that are commonly performed in a wellbore or subterranean formation.
For example, a treatment for fluid-loss control can be used during any of drilling, completion, and intervention operations. During completion or intervention, stimulation is a type of treatment performed to enhance or restore the productivity of oil or gas from a well. Stimulation treatments fall into two main groups: hydraulic fracturing and matrix treatments. Fracturing treatments are performed above the fracture pressure of the subterranean formation to create or extend a highly permeable flow path between the formation and the wellbore. Matrix treatments are performed below the fracture pressure of the formation. Other types of completion or intervention treatments can include, for example, gravel packing, consolidation, and controlling excessive water production, and controlling sand or fines production. Still other types of completion or intervention treatments include, but are not limited to, damage removal, formation isolation, wellbore cleanout, scale removal, and scale control. Of course, other well treatments and well fluids are known in the art.
Kill Pill Treatments
Fluids used during and after perforating a well during completion or intervention are usually referred to as “kill-pills.” Kill-pills can be water-based or oil-based. A typical water-based kill-pill may consist of a brine that meets density requirements and one or more of the following: a xanthan polymer for viscosity control, a starch polymer for fluid loss control, and sized calcium carbonate for bridging at the pore throats. A typical oil-based kill-pill may consist of base oil, brine as an internal phase, an emulsifier package, barite or sized calcium carbonate to meet density and bridging requirements, lime and organophilic clay for alkalinity and viscosity, respectively. In addition fluid-loss control additives are also added in oil-based muds.
Hydraulic Fracturing
Hydraulic fracturing is a common stimulation treatment. The purpose of a fracturing treatment is to provide an improved flow path for oil or gas to flow from the hydrocarbon-bearing formation to the wellbore. A treatment fluid adapted for this purpose is sometimes referred to as a fracturing fluid. The fracturing fluid is pumped at a sufficiently high flow rate and pressure into the wellbore and into the subterranean formation to create or enhance one or more fractures in the subterranean formation.
A newly-created or newly-extended fracture will tend to close together after the pumping of the fracturing fluid is stopped. To prevent the fracture from closing, a material is usually placed in the fracture to keep the fracture propped open and to provide higher fluid conductivity than the matrix of the formation. A material used for this purpose is referred to as a proppant.
A proppant is in the form of a solid particulate, which can be suspended in the fracturing fluid, carried downhole, and deposited in the fracture to form a proppant pack. The proppant pack props the fracture in an open condition while allowing fluid flow through the permeability of the pack. The proppant pack in the fracture provides a higher-permeability flow path for the oil or gas to reach the wellbore compared to the permeability of the matrix of the surrounding subterranean formation. This higher-permeability flow path increases oil and gas production from the subterranean formation.
A particulate for use as a proppant is usually selected based on the characteristics of size range, crush strength, and solid stability in the types of fluids that are encountered or used in wells. Preferably, a proppant should not melt, dissolve, or otherwise degrade from the solid state under the downhole conditions.
Gravel Packing
Gravel packing is commonly used as a sand-control method to prevent production of formation sand or other fines from a poorly consolidated subterranean formation. In this context, “fines” are tiny particles, typically having a diameter of 43 microns or smaller, that have a tendency to flow through the formation with the production of hydrocarbon. The fines have a tendency to plug small pore spaces in the formation and block the flow of oil. As all the hydrocarbon is flowing from a relatively large region around the wellbore toward a relatively small area around the wellbore, the fines have a tendency to become densely packed and screen out or plug the area immediately around the wellbore. Moreover, the fines are highly abrasive and can be damaging to pumping and oilfield other equipment and operations.
Placing a relatively larger particulate near the wellbore helps filter out the sand or fine particles and prevents them from flowing into the well with the produced fluids. The primary objective is to stabilize the formation while causing minimal impairment to well productivity.
The particulate used for this purpose is referred to as “gravel.” In the oil and gas field, and as used herein, the term “gravel” is refers to relatively large particles in the sand size classification, that is, particles ranging in diameter from about 0.1 mm up to about 2 mm. Generally, a particulate having the properties, including chemical stability, of a low-strength proppant is used in gravel packing. An example of a commonly used gravel packing material is sand having an appropriate particulate size range.
In one common type of gravel packing, a mechanical screen is placed in the wellbore and the surrounding annulus is packed with a particulate of a larger specific size designed to prevent the passage of formation sand or other fines. It is also common, for example, to gravel pack after a fracturing procedure, and such a combined procedure is sometimes referred to as a “frac-packing.”
Fluid-loss Control
Fluid loss refers to the undesirable leakage of a fluid phase of any type of well fluid into the permeable matrix of a zone, which zone may or may not be a treatment zone. Fluid-loss control refers to treatments designed to reduce such undesirable leakage. Providing effective fluid-loss control for well fluids during certain stages of well operations is usually highly desirable.
The usual approach to fluid-loss control is to substantially reduce the permeability of the matrix of the zone with a fluid-loss control material that blocks the permeability at or near the face of the rock matrix of the zone. For example, the fluid-loss control material may be a particulate that has a size selected to bridge and plug the pore throats of the matrix. All else being equal, the higher the concentration of the particulate, the faster bridging will occur. As the fluid phase carrying the fluid-loss control material leaks into the formation, the fluid-loss control material bridges the pore throats of the matrix of the formation and builds up on the surface of the borehole or fracture face or penetrates only a little into the matrix. The buildup of solid particulate or other fluid-loss control material on the walls of a wellbore or a fracture is referred to as a filter cake. Depending on the nature of a fluid phase and the filter cake, such a filter cake may help block the further loss of a fluid phase (referred to as a filtrate) into the subterranean formation. A fluid-loss control material is specifically designed to lower the volume of a filtrate that passes through a filter medium.
After application of a filter cake, however, it may be desirable to restore permeability into the formation. If the formation permeability of the desired producing zone is not restored, production levels from the formation can be significantly lower. Any filter cake or any solid or polymer filtration into the matrix of the zone resulting from a fluid-loss control treatment must be removed to restore the formation's permeability, preferably to at least its original level. This is often referred to as clean up.
A variety of fluid-loss control materials have been used and evaluated for fluid-loss control and clean-up, including foams, oil-soluble resins, acid-soluble solid particulates, graded salt slurries, linear viscoelastic polymers, and heavy metal-crosslinked polymers. Their respective comparative effects are well documented.
Fluid-loss control materials are sometimes used in drilling fluids or in treatments that have been developed to control fluid loss. A fluid-loss control pill is a treatment fluid that is designed or used to provide some degree of fluid-loss control. Through a combination of viscosity, solids bridging, and cake buildup on the porous rock, these pills oftentimes are able to substantially reduce the permeability of a zone of the subterranean formation to fluid loss. They also generally enhance filter-cake buildup on the face of the formation to inhibit fluid flow into the formation from the wellbore.
Increasing Viscosity of a Well Fluid
“Carrier” Fluid for Particulate
Increasing the viscosity of a well fluid can be useful for several purposes.
For example, during drilling, rock cuttings should be carried uphole by the drilling fluid and flowed out of the wellbore. The rock cuttings typically have specific gravity greater than 2, which is much higher than that of many drilling fluids. These high-density cuttings have a tendency to separate from water or oil very rapidly.
Similarly, a proppant used in fracturing or a gravel used in gravel packing may have a much different density than the carrier fluid. For example, sand has a specific gravity of about 2.7, whereas water has a specific gravity of 1.0 at Standard Laboratory conditions of temperature and pressure. A proppant or gravel having a different density than water will tend to separate from water very rapidly.
As many well fluids are water-based, partly for the purpose of helping to suspend particulate of higher density, and for other reasons known in the art, the density of the fluid used in a well can be increased by including highly water-soluble salts in the water, such as potassium chloride. However, increasing the density of a well fluid will rarely be sufficient or effective to match the density of the particulate.
Increasing Viscosity of Fluid for Suspending Particulate
Increasing the viscosity of a well fluid can help prevent a particulate having a different specific gravity than an external phase of the fluid from quickly separating out of the external phase.
A viscosity-increasing agent can be used to increase the ability of a fluid to suspend and carry a particulate material in a well fluid. A viscosity-increasing agent can be used for other purposes, such as matrix diversion or conformance control.
A viscosity-increasing agent is sometimes referred to in the art as a viscosifying agent, viscosifier, thickener, gelling agent, or suspending agent. In general, any of these refers to an agent that includes at least the characteristic of increasing the viscosity of a fluid in which it is dispersed or dissolved. There are several kinds of viscosity-increasing agents and related techniques for increasing the viscosity of a fluid.
In general, because of the high volume of fracturing fluid typically used in a fracturing operation, it is desirable to efficiently increase the viscosity of fracturing fluids to the desired viscosity using as little viscosity-increasing agent as possible. In addition, relatively inexpensive materials are preferred. Being able to use only a small concentration of the viscosity-increasing agent requires a lesser amount of the viscosity-increasing agent in order to achieve the desired fluid viscosity in a large volume of fracturing fluid.
Polymers for Increasing Viscosity
Certain kinds of polymers can be used to increase the viscosity of a fluid. In general, the purpose of using a polymer is to increase the ability of the fluid to suspend and carry a particulate material. Polymers for increasing the viscosity of a fluid are preferably soluble in the external phase of a fluid. Polymers for increasing the viscosity of a fluid can be naturally occurring polymers such as polysaccharides, derivatives of naturally occurring polymers, or synthetic polymers.
Crosslinking of Polymer to Increase Viscosity of a Fluid or Form a Gel
The viscosity of a fluid at a given concentration of viscosity-increasing agent can be greatly increased by crosslinking the viscosity-increasing agent. A crosslinking agent, sometimes referred to as a crosslinker, can be used for this purpose. A crosslinker interacts with at least two polymer molecules to form a “crosslink” between them.
If crosslinked to a sufficient extent, the polysaccharide may form a gel with water. Gel formation is based on a number of factors including the particular polymer and concentration thereof, the particular crosslinker and concentration thereof, the degree of crosslinking, temperature, and a variety of other factors known to those of ordinary skill in the art.
For example, one of the most common viscosity-increasing agents used in the oil and gas industry is guar. A mixture of guar dissolved in water forms a base gel, and a suitable crosslinking agent can be added to form a much more viscous fluid, which is then called a crosslinked fluid. The viscosity of base gels of guar is typically about 20 to about 50 cp. When a base gel is crosslinked, the viscosity is increased by 2 to 100 times depending on the temperature, the type of viscosity testing equipment and method, and the type of crosslinker used.
The degree of crosslinking depends on the type of viscosity-increasing polymer used, the type of crosslinker, concentrations, temperature of the fluid, etc. Shear is usually required to mix the base gel and the crosslinking agent. Thus, the actual number of crosslinks that are possible and that actually form also depends on the shear level of the system. The exact number of crosslink sites is not well known, but it could be as few as one to about ten per polymer molecule. The number of crosslinks is believed to significantly alter fluid viscosity.
For a polymeric viscosity-increasing agent, any crosslinking agent that is suitable for crosslinking the chosen monomers or polymers may be used.
Problem with Certain Hydratable Agents and Certain Dissolved Ions in Water
Most, if not all, of the commonly used water-soluble viscosity-increasing agents, water-soluble friction-reducing agents, and water-soluble elasticity-increasing agents are hydratable. As referred to herein, “hydratable” means capable of being hydrated by contacting the hydratable agent with water. Regarding a hydratable agent that comprises a polymer, this means, among other things, to associate sites on the polymer with water molecules and to unravel and extend the polymer chain in the water. Viscosity-increasing agents have been conventionally hydrated directly in the water at the concentration to be used for the well fluid.
A common problem with using hydratable agents is that many of the commonly-used hydratable polymers used for such purposes are sensitive to dissolved ions in the water. The hydratable agents are often especially sensitive to divalent cations such as calcium and magnesium. For example, divalent cations such as calcium and magnesium may inhibit and slow the time required for hydration of certain types of polymers commonly used for such purposes. In the context of hydratable polymers, a water having total dissolved solids of more than 0.67 lb/gal (80 g/l), such that the density of the water with the total dissolved solids is more than 9.0 lb/gal, is generally considered too high for many types of hydratable polymers. Some hydratable polymers may be sensitive to lower concentrations of TDS.
Problem with Fluid Damage to Proppant Pack or Matrix Permeability
In well treatments using viscous well fluids, the material for increasing the viscosity of the fluid can damage the permeability of the proppant pack or the matrix of the subterranean formation. For example, a fracturing fluid can include a polymeric material that is deposited in the fracture or within the matrix. By way of another example, the fluid may include surfactants that leave unbroken micelles in the fracture or change the wettability of the formation in the region of the fracture.
Breakers are utilized in many treatments to mitigate fluid damage in the formation. However, breakers and other treatments are subject to variability of results, they add expense and complication to a fracture treatment, and in can still leave at least some fluid damage in the formation.
Breaker for Viscosity of Fluid with Polysaccharide or Crosslinked Polysaccharide
After a treatment fluid is placed where desired in the well and for the desired time, the fluid usually must be removed from the wellbore or the formation. For example, in the case of hydraulic fracturing, the fluid should be removed leaving the proppant in the fracture and without damaging the conductivity of the proppant bed. To accomplish this removal, the viscosity of the treatment fluid must be reduced to a very low viscosity, preferably near the viscosity of water, for optimal removal from the propped fracture. Similarly, when a viscosified fluid is used for gravel packing, the viscosified fluid must be removed from the gravel pack.
Reducing the viscosity of a viscosified fluid is referred to as “breaking” the fluid. Chemicals used to reduce the viscosity of fracturing fluids are called breakers. Other types of viscosified well fluids also need to be broken for removal from the wellbore or subterranean formation.
No particular mechanism is necessarily implied by the term. For example, a breaker can reduce the molecular weight of a water-soluble polymer by cutting the long polymer chain. As the length of the polymer chain is cut, the viscosity of the fluid is reduced. For instance, reducing the guar polymer molecular weight to shorter chains having a molecular weight of about 10,000 converts the fluid to near water-thin viscosity. This process can occur independently of any crosslinking bonds existing between polymer chains.
In the case of a crosslinked viscosity-increasing agent, for example, one way to diminish the viscosity is by breaking the crosslinks. For example, the borate crosslinks in a borate-crosslinked polymer can be broken by lowering the pH of the fluid. At a pH above 8, the borate ion exists and is available to crosslink and cause an increase in viscosity or gelling. At a lower pH, the borate ion reacts with proton and is not available for crosslinking, thus, an increase in viscosity due to borate crosslinking is reversible. In contrast, crosslinks formed by zirconium, titanium, antimony, and aluminum compounds, however, are such crosslinks are considered to be non-reversible and are broken by other methods than controlling pH.
Thus, removal of the treatment fluid is facilitated by using one or more breakers to reduce fluid viscosity.
Unfortunately, another complicating factor exists. Because of the large size of the polymer, a filtration process can occur upon the face of a formation or fracture in conventional formation. A filtercake of the polymer can be formed while the aqueous fluid, KCl, and breakers pass into the matrix of the formation. Careful examination of this filtercake, which may be formed from crosslinked or uncrosslinked guar or other polymer, reveals a semi-elastic, rubberlike membrane. Once the polymer concentrates, it is difficult to solubilize the polymer. Nonfiltercake fluid consists of approximately 99.5 percent water and 0.5 percent polymer. Accordingly, for example, when the fracture closes in a fracturing treatment, the permeability of the proppant bed or the formation face may be severely damaged by the polymer filtercake. Viscosified gravel pack fluids need breakers, too. They may or may not form a filtercake on the formation face.
Breakers must be selected to meet the needs of each situation. First, it is important to understand the general performance criteria of breakers. In reducing the viscosity of the treatment fluid to a near water-thin state, the breaker must maintain a critical balance. Premature reduction of viscosity during the pumping of a treatment fluid can jeopardize the treatment. Inadequate reduction of fluid viscosity after pumping can also reduce production if the required conductivity is not obtained.
In fracturing, for example, the ideal viscosity versus time profile would be if a fluid maintained 100% viscosity until the fracture closed on proppant and then immediately broke to a thin fluid. Some breaking inherently occurs during the 0.5 to 4 hours required to pump most fracturing treatments. One guideline for selecting an acceptable breaker design is that at least 50% of the fluid viscosity should be maintained at the end of the pumping time. This guideline may be adjusted according to job time, desired fracture length, and required fluid viscosity at reservoir temperature. A typical gravel pack break criteria is a minimum 4-hour break time.
Chemical breakers used to reduce viscosity of a fluid viscosified with a viscosifying polymer used in fracturing or other subterranean applications are generally grouped into three classes: oxidizers, enzymes, and acids.